Many unconsolidated heavy oil sands reservoirs in east-central Alberta and west-central Saskatchewan (the Mannville group reservoirs) have been produced under primary production by bottom water drive, using arrays of long horizontal wells drilled at the top of the reservoir. These reservoirs are typically thin, up to 1,000 m deep, may be capped by a layer of gas and underlain by an active aquifer. Oil is produced by pumping and water displaces the oil as it rises from aquifers at the base of the reservoir. Since only a relatively small volume of the reservoir is affected by conventional vertical wells, the burgeoning use of long horizontal wells with much larger reservoir contact has in the past few years improved production rates and early economics, but not recovery. Cumulative recoveries of 100,000 bbl per well have been achieved at economic production rates during their, typically, 5 year economic life. The recovery is limited by the adverse mobility ratio of heavy oil and water which leads to eventual watering out of the production when water from the aquifer lower in the reservoir breaks through by coning or cresting and the handling cost of water make the operation uneconomic. Although at that point only about 5% of the original oil in place (OOIP) had been recovered, the wells are usually abandoned.
The companies producing heavy oil in the Lloydminster area in the above manner (ie. without thermal stimulation and using horizontal or vertical wells) were initially concentrating their efforts on sand exclusion through the use of gravel packing and screens, only to shut off economic production rates. As the physical mechanisms became better understood, it became apparent that steps should be taken to encourage sand production through aggressive perforation, rather than exclude it. Primary recovery of sand laden heavy crude became known as `cold production` because heat, such as steam, is not introduced into the reservoir. Technologies were developed to cope with large initial sand cuts, keeping sand production stable and even restoring it after a blockage occured, usually in the horizontal liner section. Cold production became an economic mainstay of heavy oil production strategies for many companies because cheap, small diameter vertical or inclined wells with sand production can often sustain rates 30-90 bbl/d of oil for many years, while horizontal wells with 1000 m slotted liner completions produce at prolific initial oil rates of up to 450 bbl/d, more than enough to pay for the cost of the well and its operation. Sand production increases the rate of heavy oil production by an order of magnitude and raises recoveries from about 5% to about 12% OOIP by creating a large diameter well effect. The ideal reservoir comprises unconsolidated sand 5-15 m thick saturated with heavy oil with gas in solution and it has no free water or gas zones. Wells are generally operated at atmospheric back pressures at hole bottom thus maintaining a maximum drawdown.
The economic primary production of heavy oil is made possible by the co-production of formation sand which is dispersed in reservoir fluids and transported to the surface by artificial lift using a pump that can cope with high sand cuts without a premature wear or breakdown, such as a progressive-cavity pump with low-nitrile, flexible elastomer stator. These rotary devices have a positive displacement, are non-pulsating and are renowned for their reliability in pumping viscous sand-cut crudes.
Sand co-production is a process of continuous liquefaction of sand at a front far from the borehole and it is encouraged through wide, slotted horizontal well liners. Although the cold production mechanism is not fully understood, there are currently two accepted theories explaining the phenomenon: (1) The sand co-production creates irregular circular high permeability channels of unknown geometry or `wormholes` in the reservoir, thereby increasing both the effective permeability and wellbore radius and (2) the bottom hole pressure reduction gives rise to a viscous `foamy oil` with gas as a finely dispersed bubble phase in the oil. The foamy zone starts growing around the wellbore causing liquefaction of unconsolidated or poorly consolidated sandstone. The formation of wormholes can result in the removal of 1000 m.sup.3 of sand out of the reservoir per well over 5-10 years of stable sand production. The increased rate and recovery of heavy oil by Cold Production is a major improvement over the original concept of a straight bottom water drive, although almost 90% of the OOIP is left behind in the unswept regions of the reservoir at the end of the cold flow economic cycle. This opens up a huge window of opportunity for a process that results in a substantial additional recovery of heavy oil.
The increased drainage radius of a well resulting from a network of high permeability channels and voids left behind in the formation after the implementation of cold production has altered the properties of virgin reservoirs and creates a large area for mass transfer of solvent vapour by diffusion. The existence of these channels also means that inter-well communication is rapidly established at exceptionally low pressures if fluids are injected. These attractive characteristics can be utilized for the application of Vapex, a relatively slow, non-thermal vapour extraction method, to recover a major portion of the hydrocarbons remaining in the reservoirs. These watered-out reservoirs thus become a potential prime source of wealth for many Canadian oil companies.
Another way in which the vast interfacial area for mass trasfer, that results in high production rates in Vapex, can be established is by injecting the solvent vapour into a high permeability aquifer at the base of a virgin reservoir and allowing it to spread as a blanket of solvent vapour between the horizontal injector and horizontal producer, forming a planar well. The high permeability of bottom water serves as a means for providing the initial injectivity. The buoyancy of the vapour results in the formation of rising solvent chambers which increase extensively the already large interfacial contact area. The feeding of these finger-like convection cells occurs vertically as a result of gravity difference between lighter solvent vapour and heavier mobilized oil. The mobilized oil solution is heavier than the solvent vapour and it drains under gravity. The mobile water layer underrides the lighter diluted oil and assists in moving it towards the production well.